Alberta Reliability Standards - AESO€¦ · 2019-01-01 · R2.1 CPS2 relates to a bound on the...

Alberta Reliability Standards

Updated: January 1, 2019

Alberta Reliability Standards CONTENTS

Effective: 2019-01-01

CONTENTS BAL Resource and Demand Balancing BAL-001-AB-0a Real Power Balancing Control Performance

BAL-002-AB-1 Disturbance Control Performance

BAL-002-WECC-AB1-2 Contingency Reserve

BAL-003-AB-0a Frequency Response Bias

BAL-004-WECC-AB-2 Automatic Time Error Correction

BAL-005-AB3-0.2b Automatic Generation Control

BAL-006-AB-1 Inadvertent Interchange

CIP Critical Infrastructure Protection CIP-SUPP-001-AB1 Cyber Security – Supplemental CIP Alberta Reliability Standard

CIP-SUPP-002-AB Cyber Security – Supplemental CIP Alberta Reliability Standard Technical Feasibility Exceptions

CIP-002-AB-5.1 Cyber Security – BES Cyber System Categorization

CIP-003-AB-5 Cyber Security – Security Measurement Controls

CIP-004-AB-5.1 Cyber Security – Personnel & Training

CIP-005-AB-5 Cyber Security – Electronic Security Perimeter(s)

CIP-006-AB-5 Cyber Security – Physical Security of BES Cyber Systems

CIP-007-AB-5 Cyber Security – System Security Management

CIP-008-AB-5 Cyber Security – Incident Reporting and Response

CIP-009-AB-5 Cyber Security – Recovery Plans for BES Cyber Systems

CIP-010-AB-1 Cyber Security – Configuration Change Management and Vulnerability Assessments

CIP-011-AB-1 Cyber Security – Information Protection

CIP-PLAN-AB-1 Cyber Security – Implementation Plan for Version 5 CIP Security Standards

COM Communications COM-001-AB1-1.1 Telecommunications

COM-002-AB1-2a Communications and Coordination



EOP Emergency Preparedness and Operations EOP-001-AB1-2.1b Emergency Operations Planning

EOP-002-AB1-2 Capacity and Energy Emergencies

EOP-003-AB1-1 Load Shedding Plans

EOP-004-AB-2 Event Reporting

EOP-005-AB-2 System Restoration from Blackstart Resources

EOP-006-AB-2 System Restoration Coordination

FAC Facilities Design, Connections and Maintenance FAC-001-AB-0 Facility Connection Requirements

FAC-002-AB-0 Coordination of Plans for New Facilities

FAC-003-AB1-1 Transmission Vegetation Management Program

FAC-008-AB-3 Facility Ratings

FAC-010-AB1-2.1 System Operating Limits Methodology for the Planning Horizon

FAC-011-AB-2 System Operating Limits Methodology for the Operations Horizon

FAC-014-AB1-2 Establish and Communicate System Operating Limits

FAC-501-WECC-AB2-1 Transmission Maintenance

INT Interchange Scheduling and Coordination INT-006-AB-2 Response to Interchange Authority

INT-009-AB-2.1 Implementation of Interchange

INT-010-AB-2.1 Interchange Initiation and Modification for Reliability

IRO Interconnection Reliability Operations and Coordination IRO-001-AB1-1.1 Reliability Coordination Responsibilities and Authorities

IRO-002-AB-2 Reliability Coordination Facilities

IRO-003-AB-2 Reliability Coordination Wide Area View

IRO-005-AB-3.1 Reliability Coordination Current Day Operations

IRO-006-AB-5 Reliability Coordination Transmission Loading Relief

IRO-006-WECC-AB-2 Qualified Transfer Path Unscheduled Flow Relief

IRO-008-AB-1 Reliability Coordinator Operational Analysis and Real-time Assessments

IRO-009-AB-1 Reliability Coordinator Actions to Operate Within IROLs

IRO-010-AB-1a Reliability Coordinator Data Specification and Collection

IRO-014-AB-1 Procedures, Processes, or Plans to Support Coordination Between Reliability Coordinators



IRO-015-AB-1 Notifications and Information Exchange Between Reliability Coordinators

IRO-016-AB-1 Coordination of Real-Time Activities Between Reliability Coordinators

MOD Modeling, Data and Analysis MOD-010&012-AB-0 Steady-State and Dynamic Data for Transmission System

Modeling and Simulation

MOD-031-AB-2 Demand and Energy Data

PER Personnel Performance, Training, and Qualifications PER-003-AB-1 Operations Personnel Credentials

PER-004-AB-2 Reliability Coordination – Staffing

PER-005-AB-2 Operations Personnel Training

PRC Protection and Control PRC-001-AB3-1.1(ii) Protection System Coordination

PRC-004-AB1-1 Analysis and Mitigation of Transmission and Generation Protection System Misoperation

PRC-004-WECC-AB1-1 Protection System and Remedial Action Scheme Misoperation

PRC-009-AB-0 Underfrequency Load Shedding Performance Following an Underfrequency Event

PRC-010-AB-0 Assessment of the Design and Effectiveness of Under Voltage Load Shed Program

PRC-018-AB-1 Disturbance Monitoring Equipment Installation and Data Reporting

PRC-021-AB1-1 Under Voltage Load Shed Program Data

PRC-022-AB-1 Under Voltage Load Shedding Program Performance

PRC-023-AB-2 Transmission Relay Loadability

TOP Transmission Operations TOP-005-AB3-1 Operational Reliability Information

TPL Transmission Planning TPL-001-AB-0 System Performance Under Normal Conditions

TPL-002-AB1-0 System Performance Following Loss of a Single BES Element

TPL-003-AB-0 System Performance Following Loss of Two or More Bulk Electric System Elements

TPL-004-AB-0 System Performance Following Extreme Bulk Electric System Events



VAR Voltage and Reactive VAR-001-AB-4 Voltage and Reactive Control

VAR-002-AB-3 Generator Operation for Maintaining Network Voltages

VAR-002-WECC-AB-1 Automatic Voltage Regulators and Voltage Regulating Systems

VAR-501-WECC-AB-1 Power System Stabilizer

Alberta Reliability Standard Resource and Demand Balancing

BAL-001-AB-0a

Effective: 2009-02-13 Page 1 of 5

BAL-001-AB-0a Real Power Balancing Control Performance

1. Purpose

The purpose of this reliability standard is to maintain WECC steady-state frequency within defined limits by balancing real power demand and supply in real-time.

2. Applicability

This reliability standard applies to:

ISO

3. Definitions

Italicized terms used in this reliability standard have the meanings as set out in the Alberta Reliability Standards Glossary of Terms and Part 1 of the ISO Rules.

4. Requirements

R1 The ISO must operate such that, on a rolling 12 month basis, the average of the clock-minute averages of the AIES’s ACE divided by 10B (B is the clock-minute average of the AIES’s frequency bias) times the corresponding clock-minute averages of the Interconnection’s frequency error is less than a specific limit. This limit ε12 is a constant derived from a targeted frequency bound (separately calculated for each Interconnection) that is reviewed and set as necessary by the NERC Operating Committee.

1

10

102

1

1

12

11

1

FB

ACEAVG

orFB

ACEAVG

i

i

Period

i

i

period

The equation for ACE is:

ACE = (NIA − NIS) − 10B (FA − FS) − IME

where:

NIA is the algebraic sum of actual flows on all tie lines.

NIS is the algebraic sum of scheduled flows on all tie lines.

B is the frequency bias setting (MW/0.1 Hz) for the AIES. The constant factor ten converts the frequency setting to MW/Hz.

FA is the actual frequency.

FS is the scheduled frequency. FS is normally 60 Hz but may be offset to effect manual time error corrections.

IME is the meter error correction factor typically estimated from the difference between the integrated hourly average of the net tie line flows (NIA) and the hourly

http://www.aeso.ca/rulesprocedures/17006.htmlhttp://www.aeso.ca/rulesprocedures/17006.htmlhttp://www.aeso.ca/rulesprocedures/9072.html



net interchange demand measurement (megawatt hour). This term should normally be very small or zero.

R 1.1 Control performance standard (CPS) 1 must be calculated by converting a compliance ratio to a compliance percentage as follows:

CPS1 = (2 - CF) * 100%

The frequency-related compliance factor (CF) is a ratio of all one-minute compliance parameters accumulated over 12 months divided by the target frequency bound:

2

1

12

monthCF

CF

where: ε1 is defined in Requirement R1.

The rating index CF12-month is derived from 12 months of data. The basic unit of data comes from one-minute averages of ACE (raw ACE, unadjusted for the WECC Automatic Time Error Control), frequency error and frequency bias settings.

A clock-minute average is the average of the AIES’s valid measured variable (i.e., for ACE and for frequency error) for each sampling cycle during a given clock-minute.

B

n

ACE

B

ACE uteclockincyclessampling

uteclockincyclessampling

uteclock1010

min

min

min

The AIES’s clock-minute CF becomes:

uteclock

uteclock

uteclockF

B

ACECF

min

min

min

10

Normally, sixty (60) clock-minute averages of the AIES’s ACE of the respective Interconnection’s frequency error will be used to calculate the respective hourly average compliance parameter.

hourinsamplesuteclock

uteclock

hourclock

n

CFCF

min

min

The ISO must be able to recalculate and store each of the respective clock-hour averages (CF clock-hour average-month) as well as the respective number of samples for each of the twenty-four (24) hours (one for each clock-hour, i.e., hour-ending (HE) 0100, HE 0200, ..., HE 2400).



monthindays

averageshourclockinsamplesuteone

monthindays

averageshourclockinsamplesuteonemonthaveragehourclock

month

monthindays

hourclockinsamplesuteone

monthindays

uteonehourclock

monthaveragehourclock

n

nCF

CF

n

nCF

CF

min

min

min

min

The 12-month CF becomes:

12

1

min

12

1

min

12

i

imonthinsamplesuteone

i

imonthinsamplesutesoneimonth

month

n

nCF

CF

In order to ensure that the average ACE and frequency deviation calculated for any one-minute interval is representative of that one-minute interval, it is necessary that at least 50% of both ACE and frequency deviation samples during that one-minute interval be present.

Should a sustained interruption in the recording of ACE or frequency deviation, due to loss of telemetering or computer unavailability, result in a one-minute interval not containing at least 50% of samples of both ACE and frequency deviation, that one-minute interval shall be excluded from the calculation of CPS1.

R2 The ISO must operate such that its average ACE for at least 90% of clock ten-minute periods (6 non-overlapping periods per hour) during a calendar month is within a specific limit, referred to as L10.

AVG 10 minute (ACEi ) ≤ L10

where:

L10=1.65 ε10 √(−10Bi)(−10Bs)

ε10 is a constant derived from the targeted frequency bound. It is the targeted root-mean-square (RMS) value of ten-minute average frequency error based on frequency performance over a given year. The bound, ε10, is the same for every balancing authority area within the WECC, and Bs is the sum of the frequency bias settings of the balancing authority areas in the WECC. For balancing authority areas with variable bias, this is equal to the sum of the minimum frequency bias settings.

R2.1 CPS2 relates to a bound on the ten-minute average of ACE. A compliance percentage must be calculated as follows:

10012

monthmonth

month

PeriodseUnavailablPeriodsTotal

ViolationsCPS

The violations per month are a count of the number of periods that ACE clock-ten-minutes exceeded L10. ACE clock-ten-minutes is the sum of valid ACE samples within a clock-ten-minute period divided by the number of valid samples. Violation clock-ten-minutes



= 0 if:

10

min10

10

min10

1

Ln

ACE

if

Ln

ACE

utesinsamples

utesinsamples

The ISO must report the total number of violations and unavailable periods for the month. L10 is defined in Requirement R2.

Since CPS2 requires that ACE be averaged over a discrete time period, the same factors that limit total periods per month will limit violations per month. The calculation of total periods per month and violations per month, therefore, must be discussed jointly.

A condition may arise which may impact the normal calculation of total periods per month and violations per month. This condition is a sustained interruption in the recording of ACE.

In order to ensure that the average ACE calculated for any ten-minute interval is representative of that ten-minute interval, it is necessary that at least half the ACE data samples are present for that interval. Should half or more of the ACE data be unavailable due to loss of telemetering or computer unavailability, that ten-minute interval shall be omitted from the calculation of CPS2.

5. Procedures

No procedures have been defined for this reliability standard.

6. Measures

The following measures correspond to the requirements identified in Section 4 of this reliability standard. For example, MR1 is the measure for R1.

MR1 CPS1, as defined and calculated per R1 and R1.1, is at least 100%.

MR2 CPS2, as defined and calculated per R2 and R2.1, is at least 90%.

7. Appendices

Appendix 1 CPS1 and CPS2 Data

CPS1 DATA Description Retention Requirements

ε1 A constant derived from the targeted frequency bound. This number is the same for each balancing authority area in the WECC.

Retain the value of ε1 used in CPS1 calculation.

ACEi The clock-minute average of ACE (raw ACE, unadjusted for the WECC Automatic Time Error Control)

Retain the one-minute average values of ACE (525,600 values).

Bi The frequency bias of the AIES. Retain the value(s) of Bi used in the CPS1calculation.



FA The actual measured frequency. Retain the one-minute average frequency values (525,600 values).

FS Scheduled frequency for the WECC. Retain the one-minute average frequency values (525,600 values).

CPS2 DATA Description Retention Requirements

V Number of incidents per hour in which the absolute value of ACE clock-ten-minutes is greater than L10.

Retain the values of V used in CPS2 calculation.

ε10 A constant derived from the frequency bound. It is the same for each balancing authority area within the WECC.

Retain the value of ε10 used in CPS2 calculation.

Bi The frequency bias of the AIES. Retain the value of Bi used in the CPS2 calculation.

Bs The sum of frequency bias of the balancing authority areas in the WECC. For systems with variable bias, this is equal to the sum of the minimum frequency bias setting.

Retain the value of Bs used in the CPS2 calculation. Retain the one-minute minimum bias value (525,600 values).

U Number of unavailable ten-minute periods per hour used in calculating CPS2.

Retain the number of 10-minute unavailable periods used in calculating CPS2 for the reporting period.

8. Guidelines

No Guidelines have been defined for this reliability standard.

Revision History

Date Description

2009-02-13 New Issue

Alberta Reliability Standard Disturbance Control Performance BAL-002-AB-1

Alberta Reliability Standard Page 1 Public Information

In Effect: 2012-10-01

1. Purpose

The purpose of this reliability standard is to ensure the ISO is able to utilize its contingency reserve to balance resources and demand and return interconnection frequency within defined limits following a disturbance resulting from a loss of supply.

2. Applicability

This reliability standard applies to the following:

the ISO which may meet the requirements of BAL-002-AB-1 through participation in a reserve sharing group which the ISO has designated as its agent.

3. Requirements

R1 The ISO must have access to contingency reserves to respond to disturbances resulting from a loss of supply and requiring the activation of contingency reserves except within the first sixty (60) minutes following the disturbance or except following the deployment of contingency reserves during implementation of the ISO’s capacity and energy emergency plan.

R2 The ISO must have access to contingency reserves from any, or a combination of: generating units, controllable load resources, or coordinated adjustments to interchange schedules.

R3 The ISO must have access to at least enough contingency reserves to cover its most severe single contingency.

R4 The ISO must activate sufficient contingency reserve to restore its area control error to the lesser of zero (0) or the pre-disturbance level within fifteen (15) minutes of any reportable disturbances subject to requirement R4.1.1 through R4.1.3.

R4.1.1 The ISO must treat multiple contingencies occurring within one (1) minute or less of each other as a single contingency.

R4.1.2 If the magnitude of the single contingency referred to in requirement R4.1.1 exceeds the ISO’s most severe single contingency the ISO must still consider the single contingency as a reportable disturbance but the ISO is excluded from compliance evaluation under requirement R4.

R4.1.3 If any subsequent contingency occur between one (1) minute and fifteen (15) minutes after the start of a reportable disturbance, any such subsequent contingency will be excluded from compliance evaluation under requirement R4 and the ISO must only determine compliance with requirement R4 for the initial reportable disturbance by performing a reasonable estimation of the response that would have occurred had any subsequent contingency not occurred.

R4.2 Subject to requirement R4.3, the ISO must report subsequent reportable disturbances that occur fifteen (15) minutes after the initial contingency but


In Effect: 2012-10-01

before sixty (60) minutes after the initial contingency and include such reportable disturbances in the compliance evaluation.

R4.3 If contingency reserves were rendered inadequate by responding to any prior contingency, the ISO must be able to show a good faith effort to activate available contingency reserves however the ISO is not required to successfully restore its area control error to the lesser of zero (0) or the pre-disturbance level within fifteen (15) minutes of any reportable disturbances.

R4.4 The ISO must, no later than the tenth (10th) day following the end of each calendar quarter, report all reportable disturbances for that quarter by submitting one (1) completed copy of DCS Form, “NERC Control Performance Standard Survey – All Interconnections” to the NERC Resources Subcommittee Survey contact.

R5 The ISO must use the following formula to calculate the recovery of area control error for a reportable disturbance:

MWLOSS is the MW size of the disturbance, resulting from a loss of supply, as measured at the beginning of the loss. The ISO must record the MWLOSS value as measured at the site of the loss to the extent possible. The value should not be measured as a change in area control error since governor response and automatic generation control response may introduce error.

ACEA is the pre-disturbance value of area control error measured as the average area control error over the period just prior to the start of


In Effect: 2012-10-01

the disturbance, resulting from a loss of supply, (10 and 60 seconds prior and including at least 4 scans of area control error).

ACEM is the maximum algebraic value of area control error measured within the fifteen (15) minutes following the disturbance resulting from a loss of supply.

R6 The ISO must determine its prospective most severe single contingency at least once every calendar year by reviewing any probable contingency on the interconnected electric system.

4 Measures


MR1 Evidence of having access to contingency reserves as required in requirement R1 exists. Evidence may include records of ancillary services contracts or a reserve sharing group agreement including a reserve sharing group agent appointment agreement.

MR2 Evidence of supplying contingency reserves as required in requirement R2 exists. Evidence may include records of ancillary services contracts or a reserve sharing group agreement including a reserve sharing group agent appointment agreement.

MR3 Evidence of having access to contingency reserves as required in requirement R3 exists. Evidence may include records of ancillary services contracts or a reserve sharing group agreement including a reserve sharing group agent appointment agreement.

MR4 Evidence of activating contingency reserves as required in requirement R4 exists. Evidence may include records of calculation showing the value of parameters used for calculating the percentage recovery (Ri), the calculation formula, a chart (area control area with respect to time) and the result of the calculation or a reserve sharing group agreement including a reserve sharing group agent appointment agreement.

MR4.1 Evidence of treating multiple contingencies as required in requirement R4.1 exists. Evidence may include disturbance control performance reports and records of any directive for ancillary services or a reserve sharing group agreement including a reserve sharing group agent appointment agreement.

MR4.2 Evidence of determining compliance in a multiple contingency situation as required in requirement R4.2 exists. Evidence may include records of any directive for ancillary services or a reserve sharing group agreement including a reserve sharing group agent appointment agreement.

MR4.3 Evidence of reporting additional reportable disturbances as required in requirement R4.3 exists. Evidence may include disturbance control performance reports or a reserve sharing group agreement including a reserve sharing group agent appointment agreement.


In Effect: 2012-10-01

MR5 Evidence of using the formula as required in requirement R5 exists. Evidence may include confirmation emails or a reserve sharing group agreement including a reserve sharing group agent appointment agreement.

MR6 Evidence of determining the prospective most severe single contingency as required in requirement R6 exists. Evidence may include email or ISO log sheet or a reserve sharing group agreement including a reserve sharing group agent appointment agreement.

5. Appendices

No appendices have been defined for this reliability standard.

Revision History

Effective Description

2012-10-01

Alberta Reliability Standard Contingency Reserve BAL-002-WECC-AB1-2


1. Purpose

The purpose of this reliability standard is to specify the quantity and types of contingency reserve required to ensure reliability under normal and abnormal conditions.

2. Applicability


(a) the ISO, which may meet the requirements of this reliability standard through participation in a reserve sharing group that the ISO has designated as its agent.

This reliability standard does not apply in the case of contingencies that result in the interconnected electric system losing synchronism with the western interconnection.

3. Requirements

R1 The ISO must have held, at a minimum, an average amount of contingency reserve that is:

R1.1 the greater of either:

(a) an amount equal to the loss of the most severe single contingency; or

(b) an amount equal to the sum of:

three percent (3%) of the hourly integrated amount of load, being the hourly integrated amount of net generation the ISO determines is delivered to the grid minus net actual interchange;

plus

three percent (3%) of the hourly integrated amount of net generation the ISO determines is delivered to the grid;

where “net generation the ISO determines is delivered to the grid” is equal to the sum of:

(i) generation from a generating unit or aggregated generating facility but not including unit service and station service loads;

plus

(ii) generation from an industrial complex or facility that has on-site generation but not including generation serving on-site load;

plus

(iii) generation delivered to the grid by the City of Medicine Hat;

R1.2 comprised of any combination of the operating reserve types specified below:

(a) spinning reserve;

(b) supplemental reserve;



(c) interchange transactions sourced within Alberta that the ISO designates as supplemental reserve;

(d) interchange transactions sourced external to Alberta that the ISO designates as spinning reserve or supplemental reserve and that, by agreement, is deliverable to Alberta on firm transmission service;

(e) a resource, other than a generating unit, an aggregated generating facility or load, that can provide energy or reduce energy consumption;

(f) load, including demand response resources, demand-side management resources, direct control load management, interruptible load or interruptible demand, or any other load made available for curtailment by the ISO via contract or agreement; and

(g) during capacity and energy emergencies, load that can be interrupted; and

R1.3 an amount of capacity from a resource that is capable of fully responding within ten (10) minutes;

except within the first sixty (60) minutes following a disturbance resulting from a loss of supply and requiring the activation of contingency reserve or except following the deployment of contingency reserve during implementation of the ISO’s capacity and energy emergency plan.

R2 The ISO must maintain at least fifty percent (50%) of its minimum amount of contingency reserve required in requirement R1 as spinning reserve that is immediately and automatically responsive to frequency deviations through the action of a governor or other control system.

R3 The ISO must, when operating as a sink balancing authority, maintain an amount of operating reserve, in addition to the minimum contingency reserve required in requirement R1, equal to the amount of supplemental reserve for any interchange transaction designated as part of the supplemental reserve of the source balancing authority or source reserve sharing group, except within the first sixty (60) minutes following an event requiring the activation of contingency reserve or except following the deployment of contingency reserve during implementation of the ISO’s capacity and energy emergency plan.

R4 The ISO must, when operating as a source balancing authority, maintain an amount of operating reserve, in addition to the minimum contingency reserve amounts required in requirement R1, equal to the amount and type of operating reserve for any operating reserve transactions for which it is the source balancing authority.

4. Measures

The following measures correspond to the requirements identified in section 3 of this reliability standard. For example, MR1 is the measure for requirement R1.

MR1 Evidence of having held contingency reserve as required in requirement R1 exists. Evidence may include:

(a) a reserve sharing group agreement including an agent appointment agreement, documentation of the methodology of the contingency reserve calculation, or ancillary services contracts; or



(b) records of disturbances or implementation of the ISO’s capacity and emergency plan as required in requirement R1.

MR1.1 Evidence of calculating the amount of contingency reserve as required in requirement R1.1 exists. Evidence may include records of the required and available contingency reserve.

MR1.2 Evidence of having contingency reserve that is comprised of the operating reserve types as required in requirement R1.2 exists. Evidence may include a reserve sharing group agreement including an agent appointment agreement or ancillary services contracts.

MR1.3 Evidence of having access to contingency reserve that is capable of fully responding in ten (10) minutes as required in requirement R1.3 exists. Evidence may include a reserve sharing group agreement including an agent appointment agreement or technical requirements for contingency reserve.

MR2 Evidence of maintaining at least fifty percent (50%) of the ISO’s minimum amount of contingency reserve as spinning reserve that is immediately responsive to frequency deviations as required in requirement R2 exists. Evidence may include a reserve sharing group agreement including an agent appointment agreement or records of dispatches of ancillary services.

MR3 Evidence of maintaining an amount of operating reserve as required in requirement R3 exists. Evidence may include a sworn affidavit from an appropriate ISO representative, authoritative documents that restrict or permit the transactions set out in requirement R3, documents that demonstrate the ISO was in a capacity and energy emergency, or a reserve sharing group agreement including an agent appointment agreement.

MR4 Evidence of maintaining an amount of operating reserve as required in requirement R4 exists. Evidence may include a sworn affidavit from an appropriate ISO representative or a reserve sharing group agreement including an agent appointment agreement.

Revision History

Effective Date Description

2015-07-26 Revised Applicability section to include exclusion for contingencies that result in the interconnected electric system losing synchronism with the western interconnection

2014-10-01 Initial release.

Alberta Reliability Standards Resource and Demand Balancing

BAL-003-AB-0a


BAL-003-AB-0a Frequency Response and Bias

1. Purpose

The purpose of this reliability standard is to provide a consistent method for calculating the frequency bias component of ACE.

2. Applicability


ISO

3. Definitions


4. Requirements

R1 The ISO must review its frequency bias settings by January 1 of each year, and recalculate its setting to reflect any change in the frequency response of the AIES.

R1.1. The ISO may change its frequency bias setting and the method used to determine the setting, whenever any of the factors used to determine the current bias value change.

R1.2. The ISO must report its frequency bias setting and method for determining that setting, to the NERC Operating Committee.

R2 The ISO must establish and maintain a frequency bias setting that is as close to practical or greater than the AIES’s frequency response. Frequency bias may be calculated in several ways:

R2.1. The ISO may use a fixed frequency bias value that is based on a fixed, straight-line function of tie line deviation or tie line trip event measurements versus frequency deviation. The ISO must determine the fixed value by observing and averaging the frequency response for several disturbances.

R2.2. The ISO may use a variable (linear or non-linear) frequency bias value that is based on a variable function of tie line deviation, or tie line trip event measurements to frequency deviation. The ISO must determine the variable frequency bias value by analyzing frequency response as it varies with factors such as load, generation, governor characteristics, and frequency.

R3 The ISO must operate its automatic generation control (AGC) on tie line frequency bias, unless such operation is adverse to system or Interconnection reliability.

R4 The ISO must have a monthly average frequency bias setting that is at least 1% of the AIES’s estimated yearly peak demand per 0.1 Hz change.


BAL-003-AB-0a Frequency Response and Bias


5. Procedures


6. Measures


MR1 Documentation exists to show that a review was carried out according to R1.

MR1.2 Confirmation that frequency bias setting and methods have been submitted to NERC (NERC survey or e-mail submission is sufficient).

MR2 The frequency bias setting is close to or greater than the AIES’s frequency response. The frequency response data is available for events analysis.

MR3 Energy Management System (EMS) records, which set AGC control modes of operation, are available to support R3.

MR4 A monthly average frequency bias setting and estimated yearly peak demand is available to support R4.

7. Appendices

8. Guidelines

No guidelines have been defined for this reliability standard.

Revision History

Date Description


Alberta Reliability Standard Automatic Time Error Correction BAL-004-WECC-AB-2

Effective Date: 2016-12-19 Page 1 of 2 Public

1. Purpose

The purpose of this reliability standard is to maintain the frequency of the western interconnection and to ensure that time error corrections and primary inadvertent interchange payback are effectively conducted in a manner that does not adversely affect the reliability of the western interconnection.

2. Applicability


(a) the ISO.

3. Requirements

R1 Following the conclusion of each month, the ISO must verify that the absolute value of its accumulated primary inadvertent interchange for both the monthly on peak period and the monthly off peak period are each individually less than or equal to 150% of the previous calendar year’s peak demand, where peak demand is the highest hourly integrated net energy for load.

R2 The ISO must, within ninety (90) days of discovery of an error in the calculation of hourly primary inadvertent interchange, recalculate the value of hourly primary inadvertent interchange and adjust the accumulated primary inadvertent interchange from the time of the error.

R3 The ISO must, while synchronously connected to the western interconnection, keep its automatic time error correction in service, with an allowable exception period of less than or equal to an accumulated twenty-four (24) hours per calendar quarter for automatic time error correction to be out of service.

R3.1 Notwithstanding requirement R3, the ISO may disable automatic time error correction if there is a reliability concern on the interconnected electric system while executing an automatic time error correction, and this time will not be included as part of the allowable exception period.

R4 The ISO must compute the following by fifty (50) minutes after each hour:

R4.1 the hourly primary inadvertent interchange;

R4.2 the accumulated primary inadvertent interchange; and

R4.3 the automatic time error correction term.

R5 The ISO must be able to change its automatic generation control operating mode between flat frequency, flat tie line, tie line bias, and tie line bias plus time error control, to correspond to current operating conditions.

R6 The ISO must recalculate the hourly primary inadvertent interchange and accumulated primary inadvertent interchange for the on peak and off peak periods whenever adjustments are made to hourly inadvertent interchange or the hourly change in system time error, as distributed by the Interconnection time monitor.

R7 The ISO must make the same adjustment to the accumulated primary inadvertent interchange as it did for any month-end meter reading adjustments to inadvertent interchange.

R8 The ISO must payback inadvertent interchange using automatic time error correction rather than bilateral and unilateral payback.

Alberta Reliability Standard Automatic Time Error Correction BAL-004-WECC-AB-2

Effective Date: 2016-12-19 Page 2 of 2 Public

4. Measures


MR1 Evidence of verifying the absolute value of the ISO’s accumulated primary inadvertent interchange as required in requirement R1 exists. Evidence may include, but is not limited to, data, screen shots from the WECC Interchange Tool, production of data from any other databases, spreadsheets, displays, or other equivalent evidence.

MR2 Evidence of recalculating the value of hourly primary inadvertent interchange and adjusting the accumulated primary inadvertent interchange from the time of the error as required in requirement R2 exists. Evidence may include, but is not limited to, data, screen shots from the WECC Interchange Tool, production data from any other databases, spreadsheets, displays, or other equivalent evidence.

MR3 Evidence of keeping the automatic time error correction in service as required in requirement R3 exists. Evidence may include, but is not limited to, dated archived files, historical data, or other equivalent evidence.

MR4 Evidence of computing the hourly primary inadvertent interchange, accumulated primary inadvertent interchange and automatic time error correction as required in requirement R4 exists. Evidence may include, but is not limited to, data, screen shots from the WECC Interchange Tool, data from any other databases, spreadsheets, displays, or other equivalent evidence.

MR5 Evidence of having the ability to change the automatic generation control operating mode as required in requirement R5 exists. Evidence may include, but is not limited to, snapshots of the operating interface provided in the energy management system for changing its automatic generation control operating mode, or other equivalent evidence.

MR6 Evidence of recalculating hourly primary inadvertent interchange and accumulated primary inadvertent interchange as required in requirement R6 exists. Evidence may include, but is not limited to, data, screen shots from the WECC Interchange Tool, data from any other databases, spreadsheets, displays, or other equivalent evidence.

MR7 Evidence of making the adjustments to accumulated primary inadvertent interchange as required in requirement R7 exists. Evidence may include, but is not limited to, data, screen shots of the WECC Interchange Tool, data from any other databases, spreadsheets, displays, or other equivalent evidence.

MR8 Evidence of paying back the inadvertent interchange as required in requirement R8 exists. Evidence may include, but is not limited to, historical inadvertent interchange data, data from the WECC Interchange Tool, or other equivalent evidence.

Revision History

Date Description


Alberta Reliability Standard Automatic Generation Control BAL-005-AB3-0.2b

Effective: 2017-06-12 Page 1 of 7 Public

1. Purpose

The purpose of this reliability standard is to establish the necessary related requirements for the ISO’s automatic generation control.

2. Applicability


(a) the legal owner of a transmission facility that provides frequency or intertie metering data the ISO uses for automatic generation control, which such frequency or intertie metering data is collected from the source the ISO identifies and publishes on the AESO website and may amend from time to time in accordance with the process set out in Appendix 1;

(b) the legal owner of a generating unit that provides frequency data the ISO uses for automatic generation control, which such frequency data is collected from the source the ISO identifies and publishes on the AESO website and may amend from time to time in accordance with the process set out in Appendix 1; and

(c) the ISO.

3. Requirements

R1 Intentionally left blank.

R2 Intentionally left blank.

R3 The ISO must, when providing regulation service, have adequate metering, communications, and control equipment employed to prevent such regulation service from becoming a burden on the interconnection or other balancing authority areas.

R4 The ISO must, when providing regulation service, notify the host balancing authority for which it is providing regulating service if it is unable to provide the regulation service and must also notify any intermediate balancing authorities.

R5 The ISO must, when receiving regulation service, have backup plans in place to provide replacement regulation service should the supplying balancing authority no longer be able to provide this service.

R6 The ISO must include the calculation of area control error, which compares total net actual interchange to total net scheduled interchange plus frequency bias obligation, in the design of its automatic generation control, except that the ISO may include an alternative calculation of area control error in the design of its automatic generation control for periods in which the ISO operates the interconnected electric system asynchronously.

R7 Subject to requirement R7.1, the ISO must operate its automatic generation control continuously.

R7.1 The ISO must, if automatic generation control has become inoperative or operation of automatic generation control could adversely impact the reliability of the interconnection, use manual controls to adjust generation to maintain the net scheduled interchange.

R8 The ISO must use a design scan rate of no more than nine (9) seconds in acquiring data necessary to calculate area control error.

R8.1 The ISO must use frequency data from redundant and independent frequency metering equipment that automatically activates upon detection of failure of the primary source; and



R8.2 The ISO must provide frequency metering data to its automatic generation control with a minimum availability of 99.95%.

R9 Subject to requirement R9.1, the ISO must include all interchange schedules with adjacent balancing authorities in the ISO’s calculation of net scheduled interchange for the area control error calculation.

R9.1 The ISO may omit the interchange schedule for a high voltage direct current link to another balancing authority from the area control error calculation if such interchange schedule is modeled by the ISO as internal generation or load.

R10 The ISO must include all dynamic schedules in the calculation of net scheduled interchange for the area control error calculation.

R11 The ISO must include the effect of ramp rates, which must be identical and agreed to between affected balancing authorities, in the scheduled interchange values to calculate the area control error.

R12 The ISO must include all interconnection flows of real power in the area control error calculation, except those flows that are excluded by the application of requirement R9.1.

R12.1 The ISO must use MW metering data for each interconnection that:

(a) emanates from a common, agreed-upon source using common primary metering equipment; and

(b) is telemetered to its system coordination centre and the control centre of the adjacent balancing authority;

R12.2 The legal owner of a transmission facility must not filter:

(a) MW metering data for interconnections; or

(b) area control error signals transmitted to the ISO, except for the anti-aliasing filters of interconnections;

R12.3 The ISO must use unfiltered:

(a) MW metering data for interconnections; or

(b) area control error signals;

provided by the legal owner of a transmission facility for calculating the ISO’s performance under the control performance standard, except for the anti-aliasing filters of interconnections; and

R12.4 The ISO must ensure that common metering equipment is installed where dynamic schedules or pseudo-ties are implemented between two (2) or more balancing authorities to deliver the output of jointly owned generating units or to serve remote load.

R13 The ISO must perform hourly error checks using intertie MWh meters with common time synchronization to determine the accuracy of its control equipment.

The ISO must adjust the component of the area control error that is in error, if known, or use the interchange meter error (IME) term of the area control error equation, to compensate for any metering equipment error until repairs can be made.

R14 The ISO must provide its operating personnel with real-time values for the area control error, interconnection frequency and net actual interchange with each adjacent balancing authority.



The ISO must provide its operating personnel with sufficient instrumentation and data recording equipment to facilitate the monitoring of the control performance standard, generation response and after-the-fact analysis of area performance.

R15 The ISO must have adequate and reliable backup power supplies at the ISO’s system coordination centre and at the ISO’s backup system coordination centre, which must be periodically tested, to maintain continuous operation of the automatic generation control and vital data recording equipment during loss of the normal power supply.

R16 The ISO must:

(a) sample area control error-related data at least at the same periodicity with which the area control error is calculated;

(b) flag missing or bad area control error-related data for operator display and archival purposes; and

(c) collect coincident area control error-related data to the greatest extent practical.

R17 Each legal owner of a transmission facility, legal owner of a generating unit, and the ISO must:

(a) check and calibrate its digital frequency transducer used for automatic generation control against a common reference, at least once every calendar year;

but if these transducers cannot be calibrated,

(b) cross-check its digital frequency transducer used for automatic generation control against at least two (2) other frequency transducers or pieces of equipment, calibrated by the manufacturer, at least once every calendar year; and

(c) replace any digital frequency transducer that is not accurate to within 0.001 Hz.

4. Measures


MR1 Intentionally left blank.

MR2 Intentionally left blank.

MR3 Evidence of having adequate metering, communications, and control equipment employed as required in requirement R3 exists. Evidence may include, but is not limited to, regulation service agreements or other documentation confirming that metering, communications and control equipment employed are adequate to prevent such service from becoming a burden.

MR4 Evidence of notifying the host balancing authority and any intermediate balancing authorities as required in requirement R4 exists. Evidence may include, but is not limited to, voice recordings or operator logs.

MR5 Evidence of having backup plans in place as required in requirement R5 exists. Evidence may include, but is not limited to, a dated and in effect backup plan(s).

MR6 Evidence of including area control error calculations in the design of the automatic generation control of the ISO as required in requirement R6 exists. Evidence may include, but is not limited to, the algorithm or code for automatic generation control that show the calculation of the area control error is included in the design of the automatic generation control of the ISO or other equivalent evidence.



MR7 Evidence of operating automatic generation control continuously as required in requirement R7 exists. Evidence may include, but is not limited to:

(a) data files showing the automatic generation control was operated continuously;

(b) where the automatic generation control was not operated continuously documentation of the rationale of not operating automatic generation control continuously; and

(c) operator logs and voice recordings.

MR7.1 Evidence of using manual controls to adjust generation as required in requirement R7.1 exists. Evidence may include, but is not limited to, operator logs or voice recordings.

MR8 Evidence of using a design scan rate of no more than nine (9) seconds in acquiring data necessary to calculate area control error as required in requirement R8 exists. Evidence may include, but is not limited to, documentation of data acquisition rate or other equivalent evidence.

MR8.1 Evidence of using frequency data as required in requirement R8.1 exists. Evidence may include, but is not limited to, a list of independent and redundant frequency metering equipment.

MR8.2 Evidence of providing frequency metering data as required in requirement R8.2 exists. Evidence may include, but is not limited to, records of frequency metering data availability to its automatic generation control.

MR9 Evidence of including all interchange schedules with adjacent balancing authorities in the ISO’s calculation as required in requirement R9 exists. Evidence may include, but is not limited to, the algorithm or codes of the calculation of the area control error.

MR9.1 Evidence of omitting the interchange schedule for a high voltage direct current link as allowed in requirement R9.1 exists. Evidence may include, but is not limited to, modeling data documentation showing that the omitted interchange schedule for a high voltage direct current link was modeled as internal generation or load.

MR10 Evidence of including dynamic schedules in the calculation of net scheduled interchange as required in requirement R10 exists. Evidence may include, but is not limited to, modeling data documentation showing dynamic schedules, if they exist, are included in the area control error equation.

MR11 Evidence of including the effect of ramp rates in the scheduled interchange values as required in requirement R11 exists. Evidence may include, but is not limited to:

(a) documentation showing the effect of ramp rates was included in the calculation of the area control error; and

(b) documentation showing the ramp rates were identical and agreed to between affected balancing authorities.

MR12 Evidence of including all interconnection flows of real power in the calculation as required in requirement R12 exists. Evidence may include, but is not limited to, the algorithm or codes of the calculation of the area control error.

MR12.1 Evidence of using MW metering data for interconnections as required in requirement R12.1 exists. Evidence may include, but is not limited to, measurement definition records and documentation showing the agreement on the source and metering equipment with the adjacent balancing authority.



MR12.2 Evidence of not filtering metering data or area control error signals as required in requirement R12.2 exists. Evidence may include, but is not limited to, data files showing that the MW metering data for interconnections or area control error signals transmitted to the ISO are not filtered prior to transmission.

MR12.3 Evidence of using unfiltered metering data or area control error signals as required in requirement R12.3 exists. Evidence may include, but is not limited to, data files showing that the unfiltered data received by the ISO is the same data used in the area control error calculation.

MR12.4 Evidence of ensuring that common metering equipment is installed as required in requirement R12.4 exists. Evidence may include, but is not limited to, documentation showing the agreement on the common metering equipment with the other balancing authority.

MR13 Evidence of performing MWh hourly error checks as required in requirement R13 exists. Evidence may include, but is not limited to, records of hourly error checks and records of adjustments made for each discrepancy, if any, identified in the hourly error checks.

Evidence of adjusting the component of the area control error that is in error as required in requirement R13 exists. Evidence may include, but is not limited to, files or data showing the error was included in the area control error.

MR14 Evidence of providing real-time values for area control error, interconnection frequency and net actual interchange, as required in requirement R14 exists. Evidence may include, but is not limited to, screen shots of the interface displaying the real-time data.

Evidence of providing sufficient instrumentation and data recording equipment as required in requirement R14 exists. Evidence may include, but is not limited to, a list of instrumentation, data and recording equipment and screen shots of the interface displaying the control performance standard, generation response and after-the-fact analysis of area performance.

MR15 Evidence of having adequate and reliable backup power supplies and of periodically testing these supplies as required in requirement R15 exists. Evidence may include, but is not limited to, a list of backup power supplies, a periodic testing plan for these backup power supplies and records of the tests.

MR16 Evidence of sampling, flagging and collecting area control error-related data as required in requirement R16 exists. Evidence may include, but is not limited to:

(a) algorithms of the sampling area control error-related data;

(b) screenshots of the operator display;

(c) archived files for missing or bad area control error related data; and

(d) archived files for coincident area control error data.

MR17 Evidence of checking, calibrating and replacing digital frequency transducers as required in requirement R17 exists. Evidence may include, but is not limited to:

(a) a list of digital frequency transducers used for automatic generation control;

(b) records, including the dates and measured accuracy values, of checking and calibrating against a common reference;

(c) where the manufacturer’s specification does not require calibration of these digital frequency transducers or these digital transducers cannot be calibrated, evidence to substantiate this



and records showing the dates of cross-checking against other frequency transducers or pieces of equipment and the accuracy values of these devices.

5. Appendices

Appendix 1 – Amending Process for List of Frequency Data and Intertie Metering Data

Revision History

Date Description

2017-06-12 Intial release



Appendix 1

Amending Process for List of Frequency Data and Intertie Metering Data

In order to amend the lists referenced in subsections (a) and (b) of section 2, Applicability, the ISO must:

(a) upon determining that a source of frequency or intertie metering data is to be added to the list, notify each affected legal owner of a generating unit or legal owner of a transmission facility in writing and determine an effective date, which must be no less than thirty (30) days after the date of notice, for the legal owner to meet the applicable requirements;

(b) upon determining that a source of frequency or intertie metering data is to be deleted, notify each affected legal owner of a generating unit or legal owner of a transmission facility in writing and determine an effective date for the legal owner to no longer be required to meet the applicable requirements; and

(c) post the amended list with effective dates on the AESO website.

Alberta Reliability Standards Resource and Demand Balancing

BAL-006-AB-1



1. Purpose

The purpose of this reliability standard is to define a process for monitoring the ISO to ensure that, over the long term, the AIES does not excessively depend on other balancing authority areas in the WECC for meeting its demand or interchange obligations.

2. Applicability


ISO

3. Definitions


4. Requirements

R1 The ISO must calculate and record hourly inadvertent interchange.

R2 The ISO must include all AC tie lines that connect to the AIES’s adjacent balancing authority areas in the AIES’s inadvertent interchange account.

R3 The ISO must ensure all of the AIES’s interconnection points are equipped with common megawatt hour meters, with readings provided hourly to the control centers of adjacent balancing authorities.

R4 The ISO must operate to a common net interchange schedule and net actual interchange value with its adjacent balancing authority areas, and must record these hourly quantities, with like values but opposite sign with the adjacent balancing authority areas. The ISO must calculate its inadvertent interchange based on the following:

R4.1 Subject to R5, the ISO must agree with its adjacent balancing authorities to:

R4.1.1 The hourly values of net interchange schedule.

R4.1.2 The hourly integrated megawatt hour values of net actual interchange.

R4.2. The ISO must use the agreed upon daily and monthly accounting data to compile its monthly accumulated inadvertent interchange for the on-peak and off-peak hours of the month.

R4.3 The ISO must make after-the-fact corrections to the agreed upon daily and monthly accounting data only as needed to reflect actual operating conditions (e.g. a meter being used for control was sending bad data).




Changes or corrections based on non-reliability considerations must not be reflected in the AIES’s inadvertent interchange. After-the-fact corrections to scheduled or actual values will not be accepted without agreement of the adjacent balancing authority(ies).

R5 If the ISO cannot mutually agree with its adjacent balancing authorities on the respective net actual interchange or net scheduled interchange quantities by the 15th calendar day of the following month, the ISO must, for the purposes of dispute resolution, submit a report to the WECC Survey Contact with information describing the nature and the cause of the dispute as well as a process for correcting the discrepancy.

5. Procedures


6. Measures


MR1 Inadvertent interchange records are complete and accurate.

MR2 Records include the applicable AC tie lines.

MR3 Documents such as metering records or schematics identifying meters in place at these points, exist or are provided.

MR4 Net interchange schedule exists, is complete for all hours and applicable AC tie lines, and corresponds with the adjacent area values.

MR4.1.1 Evidence indicating agreement exists for all hourly values of the net interchange schedule.

MR4.1.2 Evidence indicating that agreement exists for all hourly integrated megawatt hour values of net actual interchange.

MR4.2 Evidence indicating that accounting data corresponds with data from net interchange schedules as well as net actual interchanges.

MR5 Dispute documents follow the specified process and timing.

7. Appendices

8. Guidelines

No guidelines have been defined for this reliability standard.

Revision History

Date Description


Alberta Reliability Standard Cyber Security – Supplemental CIP Alberta Reliability Standard CIP-SUPP-001-AB1


A. Introduction

1. Title: Cyber Security – Supplemental CIP Alberta Reliability Standard

2. Number: CIP-SUPP-001-AB1

3. Purpose: The purpose of this reliability standard is to allow the ISO to approve variances to the requirements of a CIP Cyber Security reliability standard, other than technical feasibility exceptions.

4. Applicability:

This reliability standard applies to those Responsible Entities listed in CIP-002-AB-5.1, Cyber Security – BES Cyber System Categorization, section 4, Applicability.

B. Requirements and Measures

R1 A Responsible Entity, other than the ISO, must, where it seeks a variance to the requirements of a CIP Cyber Security reliability standard, make a request in writing to the ISO outlining (i) the requirements of the particular CIP Cyber Security reliability standard in respect of which the variance is sought; (ii) the grounds in support of the requested variance, which grounds must not be frivolous or of little merit; and (iii) the requested effective dates of the variance.

M1 Evidence of a request for a variance being made in writing as required in requirement R1 exists. Evidence may include, but is not limited to, a hard copy or electronic copy of the request.

R2 The ISO and the Responsible Entity must treat a request for a variance under requirement R1, all records related to such a request, and a variance approved under requirement R3, as confidential in accordance with the provisions of section 103.1 of the ISO rules, Confidentiality, provided however that where the request for a variance is made by a Responsible Entity whose rights and obligations are the subject of a power purchase arrangement that Responsible Entity may disclose to its counterparties such information in respect of the variance as and if required under the terms of the power purchase arrangement.

R2.1 Where the ISO determines that the disclosure of a request for a variance under requirement R1, all records related to such a request, or a variance approved under requirement R3:

(a) would have no material impact on the reliability of the interconnected electric system; and

(b) does not contain information which, in the opinion of the ISO, is commercially sensitive,

requirement R2 of this standard does not apply and the ISO may publicly disclose the request and all records related to the request in accordance with subsection 2(6)(b)(i) of section 103.1 of the ISO rules.

M2 Evidence of treating the request as confidential as described in requirement R2 exists, unless requirement R2.1 applies.

Alberta Reliability Standard Cyber Security – Supplemental CIP Alberta Reliability Standard CIP-SUPP-001-AB1


R3 The ISO must, where it approves a variance requested under requirement R1:

(a) indicate the effective dates of the variance;

(b) identify the Responsible Entity to which the variance applies;

(c) maintain a copy of the variance, in writing; and

(d) provide a copy of the variance, in writing, to the Responsible Entity that has requested the variance.

M3 Evidence of taking the steps required in requirement R3 exists. Evidence may include, but is not limited to, a written copy of the variance including its effective dates, correspondence to the Responsible Entity enclosing a copy of the variance or other equivalent evidence.

R4 The ISO must not, in any event, approve a variance requested under requirement R1 unless the ISO determines, by its own assessment, that the variance has merit and will not have a material impact on the reliability of the interconnected electric system.

M4 Evidence of performing an assessment in accordance with requirement R4 exists. Evidence may include, but is not limited to, a copy of the ISO’s business practices relating to variances of a CIP Cyber Security reliability standard.

R5 The ISO must, where it does not approve a variance requested under requirement R1, provide a copy of its decision, including reasons, in writing, to the Responsible Entity that has requested the variance.

M5 Evidence of issuing a decision denying the variance requested exists. Evidence may include, but is not limited to, a hard copy or electronic copy of a letter from the ISO denying the variance requested.

R6 Notwithstanding any of the requirements of this reliability standard, a Responsible Entity must make a request for a technical feasibility exception in accordance with the provisions of CIP-SUPP-002-AB, Technical Feasibility Exceptions.

M6 Evidence of requesting a technical feasibility exception as required in requirement R6 exists. Evidence may include, but is not limited to, a hard copy or electronic copy of the request, or other equivalent evidence.

Revision History

Date Description

2017-03-21 Addition of requirement R6 and associated measure. Revision to purpose statement.


Alberta Reliability Standard Cyber Security – Supplemental CIP Alberta Reliability Standard Technical Feasibility Exceptions CIP-SUPP-002-AB


A. Introduction

1. Title: Cyber Security – Supplemental CIP Alberta Reliability Standard Technical Feasibility Exceptions

2. Number: CIP-SUPP-002-AB

3. Purpose: The purpose of this reliability standard is to allow the ISO to approve technical feasibility exceptions to the requirements of a CIP Cyber Security reliability standard.

4. Applicability:

This reliability standard applies to those Responsible Entities listed in CIP-002-AB-5.1, Cyber Security – BES Cyber System Categorization, section 4, Applicability.


R1 A Responsible Entity other than the ISO must, where:

(a) a requirement in the CIP Cyber Security reliability standards uses the phrase “where technically feasible”; and

(b) the Responsible Entity seeks a variance from the requirement referenced in sub-requirement R1(a) on the grounds of technical feasibility,

request that the ISO approve a technical feasibility exception.

MR1 Evidence of a request for a technical feasibility exception as required in requirement R1 exists. Evidence may include, but is not limited to, a hard copy or electronic copy of the request, or other equivalent evidence.

R2 A Responsible Entity must make a request under requirement R1 in writing in the form specified by the ISO.

MR2 Evidence of making a request in writing as described in requirement R1 exists. Evidence may include, but is not limited to, a hard copy or electronic copy of the request, or other equivalent evidence.

R3 At the ISO’s request, a Responsible Entity must provide:

(a) any additional information relating to a request for a technical feasibility exception; or

(b) the reasons why the additional information will not be provided.

MR3 Evidence of providing additional information or reasons in accordance with requirement R3 exists. Evidence may include, but is not limited to, a hard copy or electronic copy of the request and the response, or other equivalent evidence.

R4 The ISO and the Responsible Entity must treat a request for a technical feasibility exception under requirement R1, and all records related to such a request, as confidential in accordance with the provisions of section 103.1 of the ISO rules, Confidentiality, provided however that where the request for a technical feasibility exception is made by a Responsible Entity whose rights and obligations are the subject of a power purchase arrangement, that Responsible Entity may disclose to its counterparties such information in respect of the technical feasibility exception as and if required under the terms of the power purchase arrangement.

MR4 Evidence of treating the request as confidential as described in requirement R4 exists.

Alberta Reliability Standard Cyber Security – Supplemental CIP Alberta Reliability Standard Technical Feasibility Exceptions CIP-SUPP-002-AB


R5 The ISO must post the criteria that it considers when determining whether to approve or disapprove a request for a technical feasibility exception on the AESO website, and must notify Responsible Entities at least thirty (30) days in advance of any amendments to the criteria.

MR5 Evidence of posting the criteria and notifying Responsible Entities as described in requirement R5 exists. Evidence may include, but is not limited to, a dated copy of the AESO website posting and a dated posting in the AESO stakeholder newsletter.

R6 The ISO must, upon reviewing a Responsible Entity’s request submitted under requirement R1 and any additional information provided to the ISO, approve the request in whole or in part, or disapprove the request.

R6.1 The ISO must, where the request submitted under requirement R1 is approved, provide a copy of its decision, in writing, to the Responsible Entity that has requested the technical feasibility exception and set out:

(a) any terms and conditions of the approval; and

(b) the expiration date of the approval.

R6.2 The ISO must, where the request submitted under requirement R1 is disapproved, provide a copy of its decision, including reasons, in writing, to the Responsible Entity that has requested the technical feasibility exception.

MR6 Evidence of an approval or disapproval of the request as described in requirement R6 exists. Evidence may include but is not limited to a dated copy of the approval or disapproval.

R7 A Responsible Entity must, where there is a material change in the facts underlying the request for or approval of a technical feasibility exception, submit a revised request to the ISO under requirement R2 within sixty (60) days of becoming aware of the material change.

MR7 Evidence of submitting a revised request to the ISO in accordance with requirement R7 exists. Evidence may include, but is not limited to, a dated record of becoming aware of a material change in facts and a dated hard copy or electronic copy of the revised request, or other equivalent evidence.

R8 The ISO may, after providing written notice to the Responsible Entity, amend or terminate a technical feasibility exception prior to the expiration date of the technical feasibility exception where:

(a) a Responsible Entity does not fulfill the terms and conditions of the approval;

(b) there is a material change in the facts underlying the approval; or

(c) the Responsible Entity advises the ISO, in writing, that the technical feasibility exception is no longer required.

MR8 Evidence of amending or terminating a technical feasibility exception and providing notice prior to the expiration date of the approval as described in requirement R8 exists. Evidence may include, but is not limited to, a dated hard copy or electronic copy of the amended or terminated technical feasibility exception provided to the Responsible Entity.

Revision History

Date Description


Alberta Reliability Standard Cyber Security – BES Cyber System Categorization CIP-002-AB-5.1


Page 1 of 8

A. Introduction

1. Title: Cyber Security – BES Cyber System Categorization

2. Number: CIP-002-AB-5.1

3. Purpose: To identify and categorize BES cyber systems and their associated BES cyber assets for the application of cyber security requirements commensurate with the adverse impact that loss, compromise, or misuse of those BES cyber systems could have on the reliable operation of the bulk electric system. Identification and categorization of BES cyber systems support appropriate protection against compromises that could lead to misoperation or instability in the bulk electric system.

4. Applicability:

4.1. For the purpose of the requirements contained herein, the following list of entities will be collectively referred to as “Responsible Entities”. For requirements in this reliability standard where a specific entity or subset of entities are the applicable entity or entities, the entity or entities are specified explicitly.

4.1.1. [Intentionally left blank.]

4.1.2. a legal owner of an electric distribution system that owns one or more of the following facilities, systems, and equipment for the protection or restoration of the bulk electric system:

4.1.2.1. each underfrequency load shedding or under voltage load shed system that:

4.1.2.1.1. is part of a load shedding program that is subject to one or more requirements in a reliability standard; and

4.1.2.1.2. performs automatic load shedding under a common control system owned by the entity in subsection 4.1.2., without human operator initiation, of 300 MW or more;

4.1.2.2. each remedial action scheme where the remedial action scheme is subject to one or more requirements in a reliability standard;

4.1.2.3. each protection system (excluding underfrequency load shedding and under voltage load shed) that applies to transmission where the protection system is subject to one or more requirements in a reliability standard; and

4.1.2.4. each cranking path and group of elements meeting the initial switching requirements from a contracted blackstart resource up to and including the first point of supply and/or point of delivery of the next generating unit or aggregated generating facility to be started;

4.1.3. the operator of a generating unit and the operator of an aggregated generating facility;

4.1.4. the legal owner of a generating unit and the legal owner of an aggregated generating facility;




Page 2 of 8


4.1.7. the operator of a transmission facility;

4.1.8. the legal owner of a transmission facility; and

4.1.9. the ISO.

4.2. For the purpose of the requirements contained herein, the following facilities, systems, and equipment owned by each Responsible Entity in subsection 4.1 above are those to which these requirements are applicable. For requirements in this reliability standard where a specific type of facilities, system, or equipment or subset of facilities, systems, and equipment are applicable, these are specified explicitly.

4.2.1. One or more of the following facilities, systems and equipment that operate at, or control elements that operate at, a nominal voltage of 25 kV or less and are owned by a legal owner of an electric distribution system or a legal owner of a transmission facility for the protection or restoration of the bulk electric system:

4.2.1.1. each underfrequency load shedding or under voltage load shed system that:

4.2.1.1.1. is part of a load shedding program that is subject to one or more requirements in a reliability standard; and

4.2.1.1.2. performs automatic load shedding under a common control system owned by one or more of the entities in subsection 4.2.1, without human operator initiation, of 300 MW or more;

4.2.1.2. each remedial action scheme where the remedial action scheme is subject to one or more requirements in a reliability standard;

4.2.1.3. each protection system (excluding underfrequency load shedding and under voltage load shed) that applies to transmission where the protection system is subject to one or more requirements in a reliability standard; and

4.2.1.4. each cranking path and group of elements meeting the initial switching requirements from a contracted blackstart resource up to and including the first point of supply and/or point of delivery of the next generating unit or aggregated generating facility to be started;

4.2.2. Responsible Entities listed in subsection 4.1 other than a legal owner of an electric distribution system are responsible for:

4.2.2.1. each transmission facility that is part of the bulk electric system except each transmission facility that:

4.2.2.1.1. is a transformer with fewer than 2 windings at 100 kV or higher and does not connect a contracted blackstart resource;

4.2.2.1.2. radially connects only to load;

4.2.2.1.3. radially connects only to one or more generating units or aggregated generating facilities with a combined maximum authorized real power of less than or equal to 67.5 MW and does not connect a contracted blackstart resource; or



Page 3 of 8

4.2.2.1.4. radially connects to load and one or more generating units or aggregated generating facilities that have a combined maximum authorized real power of less than or equal to 67.5 MW and does not connect a contracted blackstart resource;

4.2.2.2. a reactive power resource that is dedicated to supplying or absorbing reactive power that is connected at 100 kV or higher, or through a dedicated transformer with a high-side voltage of 100 kV or higher, except those reactive power resources operated by an end-use customer for its own use;

4.2.2.3. a generating unit that is:

4.2.2.3.1. directly connected to the bulk electric system and has a maximum authorized real power rating greater than 18 MW unless the generating unit is part of an industrial complex;

4.2.2.3.2. within a power plant which:

4.2.2.3.2.1. is not part of an aggregated generating facility;

4.2.2.3.2.2. is directly connected to the bulk electric system; and

4.2.2.3.2.3. has a combined maximum authorized real power rating greater than 67.5 MW unless the power plant is part of an industrial complex;

4.2.2.3.3. within an industrial complex with supply transmission service greater than 67.5 MW; or

4.2.2.3.4. a contracted blackstart resource;

4.2.2.4. an aggregated generating facility that is:

4.2.2.4.1. directly connected to the bulk electric system and has a maximum authorized real power rating greater than 67.5 MW unless the aggregated generating facility is part of an industrial complex;

4.2.2.4.2. within an industrial complex with supply transmission service greater than 67.5 MW; or

4.2.2.4.3. a contracted blackstart resource;

and

4.2.2.5. control centres and backup control centres.

4.2.3. The following are exempt from this reliability standard:

4.2.3.1. [Intentionally left blank.]

4.2.3.2. cyber assets associated with communication networks and data communication links between discrete electronic security perimeters.

4.2.3.3. [Intentionally left blank.]

4.2.3.4. for the legal owner of an electric distribution system, the systems and equipment that are not included in subsection 4.2.1 above.



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5. [Intentionally left blank.]

6. [Intentionally left blank.]


R1. Each Responsible Entity shall implement a process that considers each of the following assets for purposes of parts 1.1 through 1.3:

(i) control centres and backup control centres;

(ii) transmission stations and substations;

(iii) generating units and aggregated generating facilities;

(iv) systems and facilities critical to system restoration, including contracted blackstart resources and cranking paths and initial switching requirements;

(v) remedial action schemes that support the reliable operation of the bulk electric system; and

(vi) for the legal owner of an electric distribution system or legal owner of a transmission facility, protection systems specified in Applicability subsection 4.2.1 above.

1.1. Identify each of the high impact BES cyber systems according to Attachment 1, Section 1, if any, at each asset;

1.2. Identify each of the medium impact BES cyber systems according to Attachment 1, Section 2, if any, at each asset; and

1.3. Identify each asset that contains a low impact BES cyber system according to Attachment 1, Section 3, if any (a discrete list of low impact BES cyber systems is not required).

M1. Acceptable evidence includes, but is not limited to, dated electronic or physical lists required by requirement R1, and Parts 1.1 and 1.2.

R2. The Responsible Entity shall:

2.1. review the identifications in requirement R1 and its parts (and update them if there are changes identified) at least once every 15 months, even if it has no identified items in requirement R1, and

2.2. have its CIP senior manager or delegate approve the identifications required by requirement R1 at least once every 15 months, even if it has no identified items in requirement R1.

M2. Acceptable evidence includes, but is not limited to, electronic or physical dated records to demonstrate that the Responsible Entity has reviewed and updated, where necessary, the identifications required in requirement R1 and its parts, and has had its CIP senior manager or delegate approve the identifications required in requirement R1 and its parts at least once every 15 months, even if it has none identified in requirement R1 and its parts, as required by requirement R2.



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Attachments

Attachment 1 – Impact Rating Criteria

Revision History

Date Description




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CIP-002-AB-5.1 Attachment 1

Impact Rating Criteria

The criteria defined in Attachment 1 do not constitute stand-alone compliance requirements, but are criteria characterizing the level of impact and are referenced by requirements.

1. High Impact Rating (H)

Each BES cyber system used by and located at any of the following:

1.1. the ISO’s control centre and backup control centre;

1.2. [Intentionally left blank.]

1.3. each control centre or backup control centre used to perform the functional obligations of an operator of a transmission facility for one or more of the assets that meet criterion 2.2, 2.4, 2.5, 2.8, 2.9, or 2.10; and

1.4. each control centre or backup control centre used to perform the functional obligations of the operator of a generating unit or the operator of an aggregated generating facility for one or more of the assets that meet criterion 2.1, 2.3, 2.6, 2.8, or 2.9.

2. Medium Impact Rating (M)

Each BES cyber system, not included in Section 1 above, associated with any of the following:

2.1. commissioned generation, by each group of generating units or aggregated generating facilities at a single plant location, with an aggregate maximum authorized real power rating of each of the generating units minus the station service load equal to or exceeding 1500 MW in a single Interconnection. For each group of generating units or aggregated generating facilities, the only BES cyber systems that meet this criterion are those shared BES cyber systems that could, within 15 minutes, adversely impact the reliable operation of any combination of generating units and/or aggregated generating facilities that in aggregate equal or exceed 1500 MW in a single Interconnection;

2.2. each bulk electric system reactive resource or group of resources at a single location (excluding generating units and aggregated generating facilities) with an aggregate maximum reactive power nameplate rating of 1000 MVAR or greater(excluding those at generating units or aggregated generating facilities). The only BES cyber systems that meet this criterion are those shared BES cyber systems that could, within 15 minutes, adversely impact the reliable operation of any combination of resources that in aggregate equal or exceed 1000 MVAR;

2.3. each generat

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